OKLAHOMA CITY, Oct. 30, 2018 /PRNewswire/ -- Chesapeake Energy
Corporation (NYSE:CHK) today reported financial and operational
results for the 2018 third quarter. Highlights include:
- 2018 third quarter net income available to common
stockholders of $60 million, or
$0.07 per diluted share; 2018 third
quarter adjusted net income attributable to Chesapeake of $174
million, or $0.19 per diluted
share
- 2018 third quarter cash flow from operating activities of
$504 million, up 52 percent from 2017
third quarter levels
- Average 2018 third quarter production of approximately
537,000 barrels of oil equivalent (boe) per day, up 5 percent
compared to 2017 third quarter, adjusted for asset
sales
- Average 2018 third quarter oil production of
approximately 89,000 barrels (bbls) of oil per day, up 13 percent
compared to 2017 third quarter, adjusted for asset sales, primarily
driven by higher volume growth from the Powder River Basin
(PRB)
Doug Lawler, Chesapeake's President and Chief Executive
Officer, commented, "Chesapeake
continues to make significant progress on our strategic priorities,
as demonstrated by our improved cash flow from operations, which
was more than 50 percent higher than the 2017 third quarter due to
higher average realized commodity prices and 13 percent growth in
our adjusted oil production. We plan to focus the vast majority of
our projected 2019 activity on our high-margin, higher-return oil
opportunities in the PRB and Eagle Ford Shale, while decreasing
capital and activity directed toward our natural gas portfolio,
which will generate additional free cash flow. Our capital
expenditures for 2018 remain on track, as we execute on our
priorities of reducing leverage, increasing margins and reaching
sustainable positive cash flow, and we expect continued progress in
2019."
2018 Third Quarter Results
For the 2018 third quarter, Chesapeake reported net income of $85 million and net income available to common
stockholders of $60 million, or
$0.07 per diluted share. The
company's EBITDA for the 2018 third quarter was $504 million. Adjusting for items that are
typically excluded by securities analysts, the 2018 third quarter
adjusted net income attributable to Chesapeake was $174
million, or $0.19 per diluted
share, while the company's adjusted EBITDA was $594 million. Reconciliations of financial
measures calculated in accordance with GAAP to non-GAAP measures
are provided on pages 13 - 18 of this release.
Production expenses during the 2018 third quarter were
$2.68 per boe, compared to
$3.03 per boe in the 2017 third
quarter. The decrease was primarily a result of certain 2018 and
2017 divestitures, in addition to lower workover activity in the
Eagle Ford Shale. General and administrative expenses (including
stock-based compensation) during the 2018 third quarter were
$1.34 per boe, compared to
$1.08 per boe in the 2017 third
quarter. The increase was primarily due to less overhead allocated
to production expenses, marketing expenses and capitalized general
and administrative costs, as well as less overhead billed to
working interest owners, due to certain divestitures in 2017 and
2018. The company's gathering, processing and transportation
expenses decreased to $7.36 per boe
from $7.40 per boe during the 2017
third quarter primarily as a result of certain 2018 and 2017
divestitures, reduced fees due to restructured midstream contracts
and lower volume commitments.
Capital Spending Overview
Chesapeake incurred total
capital expenditures, including capitalized interest of
$42 million, of approximately
$619 million during the 2018 third
quarter, compared to approximately $692
million in the 2017 third quarter. A summary is provided in
the table below.
|
|
Three Months Ended September
30,
|
|
2018
|
|
2017
|
Operated activity
comparison
|
|
|
|
Average rig
count
|
19
|
|
17
|
Gross wells
spud
|
84
|
|
86
|
Gross wells
completed
|
81
|
|
120
|
Gross wells
connected
|
75
|
|
122
|
|
|
|
|
Type of cost ($ in
millions)
|
|
|
|
Drilling and
completion capital expenditures
|
$
|
549
|
|
$
|
626
|
Exploration costs,
leasehold and additions to other PP&E
|
28
|
|
17
|
Subtotal capital
expenditures
|
$
|
577
|
|
$
|
643
|
Capitalized
interest
|
42
|
|
49
|
Total capital
expenditures
|
$
|
619
|
|
$
|
692
|
Balance Sheet and Liquidity
As of September 30, 2018,
Chesapeake's principal amount of
debt outstanding was approximately $9.862
billion, compared to $9.981
billion as of December 31,
2017. Also as of September 30,
2018, the company had $645
million of outstanding borrowings and $182 million for various letters of credit under
its senior secured revolving credit facility resulting in
approximately $2.2 billion of
available liquidity under the facility.
Chesapeake continues to focus
on reducing future interest expense charges, eliminating complexity
and simplifying its balance sheet. On September 12, 2018, the company amended and
restated its senior secured revolving credit facility with an
initial borrowing base of $3.0
billion maturing in September
2023. The collateral securing the initial borrowing base
does not include any properties sold in the company's $2.0 billion Utica Shale transaction, which
closed in October 2018, therefore the
borrowing base was not affected.
On September 27, 2018, the company
issued $1.25 billion of senior notes,
consisting of $850 million of 7.00%
senior notes due 2024 and $400
million of 7.50% senior notes due 2026. Chesapeake used the net proceeds from the
offering, together with borrowings under its revolving credit
facility, to repay its secured term loan due 2021 which carried a
floating interest rate equating to approximately 9.60%, in its
entirety. The impact of this refinancing is projected to result in
cash interest expense savings of approximately $30 million in 2019.
On October 29, 2018, the company
delivered a notice of redemption to the trustee for its 8.00%
Senior Secured Second Lien Notes due 2022 to call for redemption
approximately $1.416 billion
aggregate principal amount of the outstanding notes, representing
100% of the aggregate principal amount of the outstanding notes.
The settlement of the redemption is expected to occur approximately
30 days from the notice delivery date and be funded with proceeds
from the sale of the company's Utica Shale assets in Ohio.
Operations Update
Chesapeake's average daily
production for the 2018 third quarter was approximately 537,000 boe
compared to approximately 542,000 boe in the 2017 third quarter.
The following tables show average daily production and average
daily sales prices received by the company's operating divisions
for the 2018 and 2017 third quarters, respectively.
|
|
Three Months Ended
September 30, 2018
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
812
|
|
|
2.46
|
|
|
—
|
|
|
—
|
|
|
135
|
|
|
25
|
|
|
14.74
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
769
|
|
|
2.74
|
|
|
—
|
|
|
—
|
|
|
128
|
|
|
24
|
|
|
16.44
|
|
Eagle Ford
|
|
58
|
|
|
74.40
|
|
|
122
|
|
|
3.26
|
|
|
22
|
|
|
28.95
|
|
|
100
|
|
|
19
|
|
|
53.43
|
|
Utica
|
|
10
|
|
|
67.09
|
|
|
488
|
|
|
2.92
|
|
|
28
|
|
|
29.39
|
|
|
119
|
|
|
22
|
|
|
24.33
|
|
Mid-Continent
|
|
9
|
|
|
69.41
|
|
|
66
|
|
|
2.50
|
|
|
4
|
|
|
29.40
|
|
|
25
|
|
|
5
|
|
|
37.68
|
|
Powder River
Basin
|
|
12
|
|
|
69.23
|
|
|
73
|
|
|
2.50
|
|
|
5
|
|
|
27.89
|
|
|
29
|
|
|
5
|
|
|
39.79
|
|
Retained
assets(a)
|
|
89
|
|
|
72.39
|
|
|
2,330
|
|
|
2.69
|
|
|
59
|
|
|
29.10
|
|
|
536
|
|
|
100
|
|
|
26.92
|
|
Divested
assets
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2.02
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
19.17
|
|
Total
|
|
89
|
|
|
72.39
|
|
|
2,332
|
|
|
2.69
|
|
|
59
|
|
|
29.09
|
|
|
537
|
|
|
100
|
%
|
|
26.92
|
|
|
|
|
|
|
Three Months Ended
September 30, 2017
|
|
|
Oil
|
|
Natural
Gas
|
|
NGL
|
|
Total
|
|
|
mbbl
per
day
|
|
$/bbl
|
|
mmcf
per
day
|
|
$/mcf
|
|
mbbl
per
day
|
|
$/bbl
|
|
mboe
per
day
|
|
%
|
|
$/boe
|
Marcellus
|
|
—
|
|
|
—
|
|
|
748
|
|
|
1.96
|
|
|
—
|
|
|
—
|
|
|
125
|
|
|
23
|
|
|
11.76
|
|
Haynesville
|
|
—
|
|
|
—
|
|
|
804
|
|
|
2.77
|
|
|
—
|
|
|
—
|
|
|
134
|
|
|
25
|
|
|
16.63
|
|
Eagle Ford
|
|
52
|
|
|
49.08
|
|
|
136
|
|
|
3.25
|
|
|
18
|
|
|
23.07
|
|
|
92
|
|
|
17
|
|
|
36.91
|
|
Utica
|
|
12
|
|
|
44.18
|
|
|
475
|
|
|
2.76
|
|
|
28
|
|
|
20.30
|
|
|
120
|
|
|
22
|
|
|
20.21
|
|
Mid-Continent
|
|
10
|
|
|
46.98
|
|
|
69
|
|
|
2.54
|
|
|
6
|
|
|
22.18
|
|
|
27
|
|
|
5
|
|
|
28.03
|
|
Powder River
Basin
|
|
5
|
|
|
47.12
|
|
|
35
|
|
|
2.91
|
|
|
3
|
|
|
26.77
|
|
|
14
|
|
|
2
|
|
|
31.01
|
|
Retained
assets(a)
|
|
79
|
|
|
47.96
|
|
|
2,267
|
|
|
2.52
|
|
|
55
|
|
|
21.70
|
|
|
512
|
|
|
94
|
|
|
20.94
|
|
Divested
assets
|
|
7
|
|
|
47.71
|
|
|
115
|
|
|
2.47
|
|
|
4
|
|
|
23.63
|
|
|
30
|
|
|
6
|
|
|
23.25
|
|
Total
|
|
86
|
|
|
47.94
|
|
|
2,382
|
|
|
2.52
|
|
|
59
|
|
|
21.83
|
|
|
542
|
|
|
100
|
%
|
|
21.06
|
|
|
(a)
Includes assets retained as of September 30, 2018.
|
Momentum is building in the PRB, where additional spacing and
step-out tests further validate the exceptional rock quality,
productivity and repeatable performance of the Turner formation.
Daily net production from the basin continues to climb as
demonstrated by the 107 percent increase compared to the average
2017 third quarter daily rate and 32 percent sequential growth
compared to the 2018 second quarter. Chesapeake expects net production from the
area will reach approximately 38,000 boe per day as an exit rate in
2018, and currently projects total net annual production from the
PRB to more than double in 2019 compared to 2018.
In July 2018, Chesapeake moved to five rigs in the PRB, all
of which are currently drilling the Turner formation. The company
placed 13 wells on production during the 2018 third quarter, eight
of which were Turner wells, bringing the total number of Turner
wells on production to 24. Included was the company's best well
drilled to date in the Turner with the Wyoming 36-34-69
B TR 1H well reaching a peak 24-hour average rate of 3,133
boe per day (47 percent oil) from a 10,246-foot lateral. In the
2018 third quarter, Chesapeake
also drilled and completed three successful step-out Turner wells
located along the western periphery of its acreage position. The
wells yielded peak 24-hour production rates ranging from 1,480 to
2,725 boe per day with an average oil cut of 82 percent. With these
well results, Chesapeake has
delineated an area covering more than 50 square miles, or
approximately 60 percent of its prospective Turner acreage,
strengthening its confidence in future development plans.
The company continues to experiment with tighter spacing tests
and is currently drilling its second set of wells spaced at
approximately 1,980 feet. In April
2018, Chesapeake drilled
six Turner wells spaced at approximately 1,980 to 2,300 feet apart
and, with more than 190 days on production for each well, the
company has seen no degradation from the tighter-spaced Turner
wells compared to wells spaced at approximately 2,680 feet. The
company expects to drill additional spacing tests in 2019, as well
as move to development pad drilling in the more oil-prone (lower
gas-to-oil ratio) portion of the field.
Chesapeake expects to place an
additional 15 wells on production in the 2018 fourth quarter and is
currently projecting an additional 65 to 70 Turner wells to be
placed on production in 2019. The company is exploring the
potential of adding a sixth rig in 2019, which would likely begin
to focus on the Parkman and
Niobrara formations.
To support the company's anticipated oil production growth,
Chesapeake has recently finalized
an agreement, subject to a right of first refusal, to lower its
gathering and transporting costs by switching from trucking to
pipeline transportation. The agreement will provide for the
gathering and transportation of a portion of the company's crude
oil volumes via pipeline from its development area to Guernsey, Wyoming beginning in the 2019 second
quarter. The company's fixed-fee rate under this agreement is
approximately one-third the cost the market is presently paying to
gather and transport oil volumes to Guernsey by trucking. Chesapeake is evaluating long-haul
transportation options to take volumes to Cushing, Oklahoma, to increase market access
as production grows.
The Eagle Ford Shale in Texas
continues to deliver steady, high-margin oil volumes that receive
premium Gulf Coast pricing. While the region is typically
unaffected by major weather events, production from the area was
affected by abnormal flooding resulting in a decline in average net
oil volumes sold of approximately 1,300 bbls of oil per day for the
months of September and October 2018.
The company is currently utilizing four rigs in the Eagle Ford,
placed 29 wells on production during the 2018 third quarter and
expects to place 53 wells on production during the 2018 fourth
quarter. Chesapeake plans to add a
fifth rig in 2019, as it continues to delineate additional
opportunities in the Upper Eagle Ford and the Austin Chalk
formations.
Chesapeake's position in the
Marcellus Shale in Pennsylvania
continues to create significant free cash flow driven by higher
realized in-basin gas prices in the 2018 third quarter compared to
a year ago, enhanced completions and longer laterals. Chesapeake is currently utilizing two rigs in
the Marcellus, placed seven wells on production during the 2018
third quarter, and expects to place 25 wells on production during
the 2018 fourth quarter.
In the 2018 third quarter, Chesapeake entered into a long-term supply
agreement with a liquefied natural gas (LNG) provider for a portion
of the company's in-basin net Marcellus gas production.
Chesapeake has agreed to supply
approximately 260 to 365 million British thermal units per day of
net Marcellus gas production to the LNG provider for a 15-year
term.
In the Haynesville Shale in Louisiana, Chesapeake moved an additional rig into the
area in July and is currently utilizing four rigs, one of which is
drilling the company's second well with a proposed lateral length
of approximately 15,000 feet. Chesapeake drilled its first 15,000-foot well,
the GEPH 30&19&18-16-15 1HC, in December 2017, which was placed on production in
May, 2018. After approximately 170 days, the well is producing
approximately 24.9 million cubic feet of natural gas (mmcf) per day
and has produced a cumulative of 5.8 billion cubic feet of natural
gas (bcf). Given higher-margin oil drilling opportunities in
Chesapeake's portfolio, the
company expects to decrease its activity in the area and move to
operating one to two rigs in 2019. The company placed four wells on
production in the Haynesville Shale during the 2018 third quarter,
and expects to place seven wells on production during the 2018
fourth quarter.
In July 2018, Chesapeake announced that it entered into an
agreement to sell its interests in the Utica Shale operating area
located in Ohio for approximately
$2.0 billion, subject to certain
customary closing conditions including the receipt of third-party
consents. This transaction closed in October
2018. Chesapeake is
currently operating two rigs in the area and placed 11 Utica wells
on production during the 2018 third quarter.
|
Key Financial and
Operational Results
|
|
The table below
summarizes Chesapeake's key financial and operational results
during the 2018 third quarter as compared to results in prior
periods.
|
|
|
Three Months Ended September
30,
|
|
2018
|
|
2017
|
Barrels of oil
equivalent production (in mboe)
|
49,413
|
|
|
49,831
|
|
Barrels of oil
equivalent production (mboe/d)
|
537
|
|
|
542
|
|
Oil production (in
mbbl/d)
|
89
|
|
|
86
|
|
Average realized oil
price ($/bbl)(a)
|
58.77
|
|
|
52.33
|
|
Natural gas
production (in mmcf/d)
|
2,332
|
|
|
2,382
|
|
Average realized
natural gas price ($/mcf)(a)
|
2.69
|
|
|
2.52
|
|
NGL production (in
mbbl/d)
|
59
|
|
|
59
|
|
Average realized NGL
price ($/bbl)(a)
|
27.37
|
|
|
21.26
|
|
Production expenses
($/boe)
|
2.68
|
|
|
3.03
|
|
Gathering, processing
and transportation expenses ($/boe)
|
7.36
|
|
|
7.40
|
|
Oil -
($/bbl)
|
3.83
|
|
|
4.33
|
|
Natural Gas -
($/mcf)
|
1.33
|
|
|
1.34
|
|
NGL -
($/bbl)
|
8.59
|
|
|
7.40
|
|
Production taxes
($/boe)
|
0.69
|
|
|
0.43
|
|
General and
administrative expenses ($/boe)(b)
|
1.22
|
|
|
0.91
|
|
General and
administrative expenses (stock-based compensation) (non-cash)
($/boe)
|
0.12
|
|
|
0.17
|
|
DD&A of oil and
natural gas properties ($/boe)
|
5.54
|
|
|
4.57
|
|
DD&A of other
assets ($/boe)
|
0.35
|
|
|
0.41
|
|
Interest expense
($/boe)
|
2.56
|
|
|
2.26
|
|
Marketing gross
margin ($ in millions)
|
(19)
|
|
|
(14)
|
|
Net cash provided by
operating activities ($ in millions)
|
504
|
|
|
331
|
|
Net cash provided by
operating activities ($/boe)
|
10.20
|
|
|
6.62
|
|
Operating cash flow
($ in millions)(c)
|
482
|
|
|
337
|
|
Operating cash flow
($/boe)
|
9.75
|
|
|
6.74
|
|
Net income (loss) ($
in millions)
|
85
|
|
|
(17)
|
|
Net income (loss)
available to common stockholders ($ in millions)
|
60
|
|
|
(41)
|
|
Net income (loss) per
share available to common stockholders – diluted ($)
|
0.07
|
|
|
(0.05)
|
|
Adjusted EBITDA ($ in
millions)(d)
|
594
|
|
|
468
|
|
Adjusted EBITDA
($/boe)
|
12.01
|
|
|
9.36
|
|
Adjusted net income
attributable to Chesapeake ($ in millions)(e)
|
174
|
|
|
106
|
|
Adjusted net income
attributable to Chesapeake per
share - diluted ($ in millions)(f)
|
0.19
|
|
|
0.12
|
|
|
|
(a)
|
Includes the effects
of realized gains (losses) from hedging, but excludes the effects
of unrealized gains (losses) from hedging.
|
|
|
(b)
|
Excludes expenses
associated with stock-based compensation, which are recorded in
general and administrative expenses in Chesapeake's Condensed
Consolidated Statement of Operations.
|
|
|
(c)
|
Defined as cash flow
provided by operating activities before changes in components of
working capital and other assets and liabilities. This is a
non-GAAP measure. See reconciliation of cash provided by operating
activities to operating cash flow on page 16.
|
|
|
(d)
|
Defined as net income
(loss) before interest expense, income taxes and depreciation,
depletion and amortization expense, as adjusted to remove the
effects of certain items detailed on page 18. This is a non-GAAP
measure. See reconciliation of net income (loss) to EBITDA on page
16 and reconciliation of EBITDA to adjusted EBITDA on page
18.
|
|
|
(e)
|
Defined as net income
(loss) attributable to Chesapeake, as adjusted to remove the
effects of certain items detailed on page 13. This is a non-GAAP
measure. See reconciliation of net income to adjusted net income
(loss) available to Chesapeake on page 13.
|
|
|
(f)
|
Our presentation of
diluted adjusted net income attributable to Chesapeake per share
excludes 208 million and 206 million shares for the three months
ended September 30, 2018 and 2017, respectively, considered
antidilutive when calculating diluted earnings per
share.
|
|
|
2018 Third Quarter Financial and Operational Results
Conference Call Update
The conference call to discuss this release has been
re-scheduled on Tuesday, October 30,
2018 at 9:00 am EDT. The
telephone number to access the conference call is 877-871-3172 or
412-902-6603. The passcode for the call is 0118883. The conference
call will be webcast and can be found at www.chk.com in the
"Investors" section of the company's website.
Headquartered in Oklahoma
City, Chesapeake Energy Corporation's (NYSE: CHK) operations
are focused on discovering and developing its large and
geographically diverse resource base of unconventional oil and
natural gas assets onshore in the United
States.
This news release and the accompanying Outlook include
"forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. Forward-looking statements are statements
other than statements of historical fact. They include statements
that give our current expectations, management's outlook guidance
or forecasts of future events, production and well connection
forecasts, estimates of operating costs, anticipated capital and
operational efficiencies, planned development drilling and expected
drilling cost reductions, anticipated timing of wells to be placed
into production, general and administrative expenses, capital
expenditures, the timing of anticipated asset sales and proceeds to
be received therefrom, the expected use of proceeds of anticipated
asset sales, projected cash flow and liquidity, our
ability to enhance our cash flow and financial flexibility, plans
and objectives for future operations, the ability of our employees,
portfolio strength and operational leadership to create long-term
value, and the assumptions on which such statements are based.
Although we believe the expectations and forecasts reflected in the
forward-looking statements are reasonable, we can give no assurance
they will prove to have been correct. They can be affected by
inaccurate or changed assumptions or by known or unknown risks and
uncertainties.
Factors that could cause actual results to differ materially
from expected results include those described under "Risk Factors"
in Item 1A of our annual report on Form 10-K and any updates to
those factors set forth in Chesapeake's subsequent quarterly reports on
Form 10-Q or current reports on Form 8-K (available at
http://www.chk.com/investors/sec-filings). These risk factors
include the volatility of oil, natural gas and NGL prices; the
limitations our level of indebtedness may have on our financial
flexibility; our inability to access the capital markets on
favorable terms; the availability of cash flows from operations and
other funds to finance reserve replacement costs or satisfy our
debt obligations; downgrade in our credit rating requiring us to
post more collateral under certain commercial arrangements;
write-downs of our oil and natural gas asset carrying values due to
low commodity prices; our ability to replace reserves and sustain
production; uncertainties inherent in estimating quantities of oil,
natural gas and NGL reserves and projecting future rates of
production and the amount and timing of development expenditures;
our ability to generate profits or achieve targeted results in
drilling and well operations; leasehold terms expiring before
production can be established; commodity derivative activities
resulting in lower prices realized on oil, natural gas and NGL
sales; the need to secure derivative liabilities and the inability
of counterparties to satisfy their obligations; adverse
developments or losses from pending or future litigation and
regulatory proceedings, including royalty claims; charges incurred
in response to market conditions and in connection with our ongoing
actions to reduce financial leverage and complexity; drilling and
operating risks and resulting liabilities; effects of environmental
protection laws and regulation on our business; legislative and
regulatory initiatives further regulating hydraulic fracturing; our
need to secure adequate supplies of water for our drilling
operations and to dispose of or recycle the water used; impacts of
potential legislative and regulatory actions addressing climate
change; federal and state tax proposals affecting our industry;
potential OTC derivatives regulation limiting our ability to hedge
against commodity price fluctuations; competition in the oil and
gas exploration and production industry; a deterioration in general
economic, business or industry conditions; negative public
perceptions of our industry; limited control over properties we do
not operate; pipeline and gathering system capacity constraints and
transportation interruptions; terrorist activities and
cyber-attacks adversely impacting our operations; an interruption
in operations at our headquarters due to a catastrophic event;
certain anti-takeover provisions that affect shareholder rights;
and our inability to increase or maintain our liquidity through
debt repurchases, capital exchanges, asset sales, joint ventures,
farmouts or other means.
In addition, disclosures concerning the estimated
contribution of derivative contracts to our future results of
operations are based upon market information as of a specific date.
These market prices are subject to significant volatility. Our
production forecasts are also dependent upon many assumptions,
including estimates of production decline rates from existing wells
and the outcome of future drilling activity. Expected asset sales
may not be completed in the time frame anticipated or at all. We
caution you not to place undue reliance on our forward-looking
statements, which speak only as of the date of this news release,
and we undertake no obligation to update any of the information
provided in this release or the accompanying Outlook, except as
required by applicable law. In addition, this news release contains
time-sensitive information that reflects management's best judgment
only as of the date of this news release.
INVESTOR
CONTACT:
|
MEDIA
CONTACT:
|
Brad Sylvester,
CFA
(405) 935-8870
ir@chk.com
|
Gordon Pennoyer
(405) 935-8878
media@chk.com
|
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS
($ in millions
except per share data)
(unaudited)
|
|
|
Three Months Ended September
30,
|
|
Nine Months Ended September
30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
REVENUES:
|
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL(a)
|
|
$
|
1,199
|
|
|
$
|
979
|
|
|
$
|
3,424
|
|
|
$
|
3,727
|
|
Marketing
|
|
1,219
|
|
|
964
|
|
|
3,738
|
|
|
3,250
|
|
Total
Revenues
|
|
2,418
|
|
|
1,943
|
|
|
7,162
|
|
|
6,977
|
|
OPERATING
EXPENSES:
|
|
|
|
|
|
|
|
|
Oil, natural gas and
NGL production
|
|
132
|
|
|
151
|
|
|
417
|
|
|
426
|
|
Oil, natural gas and
NGL gathering, processing and transportation
|
|
364
|
|
|
369
|
|
|
1,060
|
|
|
1,081
|
|
Production
taxes
|
|
34
|
|
|
21
|
|
|
91
|
|
|
64
|
|
Marketing
|
|
1,238
|
|
|
978
|
|
|
3,798
|
|
|
3,333
|
|
General and
administrative
|
|
66
|
|
|
54
|
|
|
229
|
|
|
189
|
|
Restructuring and
other termination costs
|
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
Provision for legal
contingencies, net
|
|
8
|
|
|
20
|
|
|
17
|
|
|
35
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
|
274
|
|
|
228
|
|
|
813
|
|
|
627
|
|
Depreciation and
amortization of other assets
|
|
17
|
|
|
20
|
|
|
54
|
|
|
62
|
|
Impairments
|
|
5
|
|
|
3
|
|
|
51
|
|
|
3
|
|
Other operating
(income) expense
|
|
—
|
|
|
6
|
|
|
(1)
|
|
|
423
|
|
Net (gains) losses on
sales of fixed assets
|
|
—
|
|
|
(1)
|
|
|
7
|
|
|
—
|
|
Total Operating
Expenses
|
|
2,138
|
|
|
1,849
|
|
|
6,574
|
|
|
6,243
|
|
INCOME FROM
OPERATIONS
|
|
280
|
|
|
94
|
|
|
588
|
|
|
734
|
|
OTHER INCOME
(EXPENSE):
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
(127)
|
|
|
(114)
|
|
|
(367)
|
|
|
(302)
|
|
Gains on
investments
|
|
—
|
|
|
—
|
|
|
139
|
|
|
—
|
|
Gains (losses) on
purchases or exchanges of debt
|
|
(68)
|
|
|
(1)
|
|
|
(68)
|
|
|
183
|
|
Other
income
|
|
1
|
|
|
4
|
|
|
63
|
|
|
6
|
|
Total Other
Expense
|
|
(194)
|
|
|
(111)
|
|
|
(233)
|
|
|
(113)
|
|
INCOME (LOSS)
BEFORE INCOME TAXES
|
|
86
|
|
|
(17)
|
|
|
355
|
|
|
621
|
|
Income tax expense
(benefit)
|
|
1
|
|
|
—
|
|
|
(8)
|
|
|
2
|
|
NET INCOME
(LOSS)
|
|
85
|
|
|
(17)
|
|
|
363
|
|
|
619
|
|
Net income
attributable to noncontrolling interests
|
|
(1)
|
|
|
(1)
|
|
|
(3)
|
|
|
(3)
|
|
NET INCOME (LOSS)
ATTRIBUTABLE TO CHESAPEAKE
|
|
84
|
|
|
(18)
|
|
|
360
|
|
|
616
|
|
Preferred stock
dividends
|
|
(23)
|
|
|
(23)
|
|
|
(69)
|
|
|
(62)
|
|
Loss on exchange of
preferred stock
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41)
|
|
Earnings allocated to
participating securities
|
|
(1)
|
|
|
—
|
|
|
(3)
|
|
|
(7)
|
|
NET INCOME (LOSS)
AVAILABLE TO COMMON STOCKHOLDERS
|
|
$
|
60
|
|
|
$
|
(41)
|
|
|
$
|
288
|
|
|
$
|
506
|
|
EARNINGS (LOSS)
PER COMMON SHARE:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.07
|
|
|
$
|
(0.05)
|
|
|
$
|
0.32
|
|
|
$
|
0.56
|
|
Diluted
|
|
$
|
0.07
|
|
|
$
|
(0.05)
|
|
|
$
|
0.32
|
|
|
$
|
0.56
|
|
WEIGHTED AVERAGE
COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in
millions):
|
|
|
|
|
|
|
|
|
Basic
|
|
910
|
|
|
909
|
|
|
909
|
|
|
908
|
|
Diluted
|
|
911
|
|
|
909
|
|
|
909
|
|
|
908
|
|
|
|
(a)
|
See page 10 for a
reconciliation of oil, natural gas and NGL revenue before and after
the effect of financial derivatives.
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED BALANCE SHEETS
($ in
millions)
(unaudited)
|
|
|
September 30,
2018
|
|
December 31,
2017
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
4
|
|
|
$
|
5
|
|
Other current
assets
|
|
1,231
|
|
|
1,520
|
|
Total Current
Assets
|
|
1,235
|
|
|
1,525
|
|
|
|
|
|
|
Property and
equipment, net
|
|
11,177
|
|
|
10,680
|
|
Other long-term
assets
|
|
247
|
|
|
220
|
|
Total
Assets
|
|
$
|
12,659
|
|
|
$
|
12,425
|
|
|
|
|
|
|
Current
liabilities
|
|
$
|
2,976
|
|
|
$
|
2,356
|
|
Long-term debt,
net
|
|
9,380
|
|
|
9,921
|
|
Other long-term
liabilities
|
|
342
|
|
|
520
|
|
Total
Liabilities
|
|
12,698
|
|
|
12,797
|
|
|
|
|
|
|
Preferred
stock
|
|
1,671
|
|
|
1,671
|
|
Noncontrolling
interests
|
|
123
|
|
|
124
|
|
Common stock and
other stockholders' equity (deficit)
|
|
(1,833)
|
|
|
(2,167)
|
|
Total Equity
(Deficit)
|
|
(39)
|
|
|
(372)
|
|
|
|
|
|
|
Total Liabilities
and Equity
|
|
$
|
12,659
|
|
|
$
|
12,425
|
|
|
|
|
|
|
Common shares
outstanding (in millions)
|
|
914
|
|
|
909
|
|
Principal amount of
debt outstanding
|
|
$
|
9,862
|
|
|
$
|
9,981
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
SUPPLEMENTAL DATA
– OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST
EXPENSE
(unaudited)
|
|
Three Months Ended September
30,
|
|
Nine Months Ended September
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net
Production:
|
|
|
|
|
|
|
|
Oil
(mmbbl)
|
8
|
|
|
8
|
|
|
25
|
|
|
23
|
|
Natural gas
(bcf)
|
215
|
|
|
219
|
|
|
647
|
|
|
639
|
|
NGL
(mmbbl)
|
5
|
|
|
5
|
|
|
15
|
|
|
15
|
|
Oil equivalent
(mmboe)
|
50
|
|
|
50
|
|
|
148
|
|
|
145
|
|
Average daily
production (mboe)
|
537
|
|
|
542
|
|
|
540
|
|
|
532
|
|
Oil, Natural Gas
and NGL Sales ($ in millions):
|
|
|
|
|
|
|
|
Oil sales
|
$
|
594
|
|
|
$
|
379
|
|
|
$
|
1,698
|
|
|
$
|
1,140
|
|
Natural gas
sales
|
578
|
|
|
553
|
|
|
1,822
|
|
|
1,807
|
|
NGL sales
|
159
|
|
|
117
|
|
|
404
|
|
|
328
|
|
Total oil, natural
gas and NGL sales
|
$
|
1,331
|
|
|
$
|
1,049
|
|
|
$
|
3,924
|
|
|
$
|
3,275
|
|
|
|
|
|
|
|
|
|
Financial
Derivatives:
|
|
|
|
|
|
|
|
Oil derivatives –
realized gains (losses)(a)
|
(112)
|
|
|
35
|
|
|
$
|
(273)
|
|
|
79
|
|
Natural gas
derivatives – realized gains (losses)(a)
|
(1)
|
|
|
(1)
|
|
|
83
|
|
|
(53)
|
|
NGL derivatives –
realized gains (losses)(a)
|
(10)
|
|
|
(3)
|
|
|
(14)
|
|
|
(1)
|
|
Total realized gains
(losses) on financial derivatives
|
$
|
(123)
|
|
|
$
|
31
|
|
|
$
|
(204)
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
|
Oil derivatives –
unrealized gains (losses)(a)
|
12
|
|
|
(96)
|
|
|
(115)
|
|
|
45
|
|
Natural gas
derivatives – unrealized gains (losses)(a)
|
(17)
|
|
|
(3)
|
|
|
(168)
|
|
|
384
|
|
NGL derivatives –
unrealized gains (losses)(a)
|
(4)
|
|
|
(2)
|
|
|
(13)
|
|
|
(2)
|
|
Total unrealized
gains (losses) on financial derivatives
|
$
|
(9)
|
|
|
$
|
(101)
|
|
|
$
|
(296)
|
|
|
$
|
427
|
|
|
|
|
|
|
|
|
|
Total financial
derivatives
|
$
|
(132)
|
|
|
$
|
(70)
|
|
|
$
|
(500)
|
|
|
$
|
452
|
|
|
|
|
|
|
|
|
|
Total oil, natural
gas and NGL sales
|
$
|
1,199
|
|
|
$
|
979
|
|
|
$
|
3,424
|
|
|
$
|
3,727
|
|
Average Sales
Price (excluding gains (losses) on derivatives):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
$
|
72.39
|
|
|
$
|
47.94
|
|
|
$
|
68.63
|
|
|
$
|
48.53
|
|
Natural gas ($ per
mcf)
|
$
|
2.69
|
|
|
$
|
2.52
|
|
|
$
|
2.82
|
|
|
$
|
2.83
|
|
NGL ($ per
bbl)
|
$
|
29.09
|
|
|
$
|
21.83
|
|
|
$
|
26.87
|
|
|
$
|
21.28
|
|
Oil equivalent ($ per
boe)
|
$
|
26.92
|
|
|
$
|
21.06
|
|
|
$
|
26.59
|
|
|
$
|
22.53
|
|
Average Sales
Price (excluding unrealized gains (losses) on
derivatives):
|
|
|
|
|
|
|
|
Oil ($ per
bbl)
|
$
|
58.77
|
|
|
$
|
52.33
|
|
|
$
|
57.61
|
|
|
$
|
51.90
|
|
Natural gas ($ per
mcf)
|
$
|
2.69
|
|
|
$
|
2.52
|
|
|
$
|
2.94
|
|
|
$
|
2.75
|
|
NGL ($ per
bbl)
|
$
|
27.37
|
|
|
$
|
21.26
|
|
|
$
|
25.96
|
|
|
$
|
21.21
|
|
Oil equivalent ($ per
boe)
|
$
|
24.44
|
|
|
$
|
21.67
|
|
|
$
|
25.21
|
|
|
$
|
22.70
|
|
Interest Expense
($ in millions):
|
|
|
|
|
|
|
|
Interest
expense(b)
|
$
|
127
|
|
|
$
|
115
|
|
|
$
|
367
|
|
|
$
|
302
|
|
Interest rate
derivatives – realized gains(c)
|
(1)
|
|
|
(1)
|
|
|
(2)
|
|
|
(3)
|
|
Interest rate
derivatives – unrealized losses(c)
|
1
|
|
|
—
|
|
|
2
|
|
|
3
|
|
Total Interest
Expense
|
$
|
127
|
|
|
$
|
114
|
|
|
$
|
367
|
|
|
$
|
302
|
|
|
|
(a)
|
Realized gains
(losses) include the following items: (i) settlements and accruals
for settlements of undesignated derivatives related to current
period production revenues, (ii) prior period settlements for
option premiums and for early-terminated derivatives originally
scheduled to settle against current period production revenues, and
(iii) gains (losses) related to de-designated cash flow hedges
originally designated to settle against current period production
revenues. Unrealized gains (losses) include the change in fair
value of open derivatives scheduled to settle against future period
production revenues (including current period settlements for
option premiums and early terminated derivatives) offset by amounts
reclassified as realized gains (losses) during the period. Although
we no longer designate our derivatives as cash flow hedges for
accounting purposes, we believe these definitions are useful to
management and investors in determining the effectiveness of our
price risk management program.
|
|
|
(b)
|
Net of amounts
capitalized.
|
|
|
(c)
|
Realized (gains)
losses include interest rate derivative settlements related to
current period interest and the effect of (gains) losses on
early-terminated trades. Settlements of early-terminated trades are
reflected in realized (gains) losses over the original life of the
hedged item. Unrealized (gains) losses include amounts reclassified
to realized (gains) losses during the period.
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
CONDENSED
CONSOLIDATED CASH FLOW DATA
($ in
millions)
(unaudited)
|
|
Three Months Ended September
30,
|
|
Nine Months Ended September
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
Beginning cash and
cash equivalents
|
$
|
3
|
|
|
$
|
13
|
|
|
$
|
5
|
|
|
$
|
882
|
|
|
|
|
|
|
|
|
|
Net cash provided
by operating activities
|
504
|
|
|
331
|
|
|
1,595
|
|
|
273
|
|
|
|
|
|
|
|
|
|
Cash flows from
investing activities:
|
|
|
|
|
|
|
|
Drilling and
completion costs(a)
|
(502)
|
|
|
(566)
|
|
|
(1,481)
|
|
|
(1,597)
|
|
Acquisitions of
proved and unproved properties(b)
|
(53)
|
|
|
(64)
|
|
|
(244)
|
|
|
(226)
|
|
Proceeds from
divestitures of proved and unproved properties
|
11
|
|
|
242
|
|
|
395
|
|
|
1,193
|
|
Additions to other
property and equipment
|
(6)
|
|
|
(5)
|
|
|
(11)
|
|
|
(12)
|
|
Proceeds from sales
of other property and equipment
|
1
|
|
|
14
|
|
|
75
|
|
|
40
|
|
Proceeds from sales
of investments
|
—
|
|
|
—
|
|
|
74
|
|
|
—
|
|
Net cash used in
investing activities
|
(549)
|
|
|
(379)
|
|
|
(1,192)
|
|
|
(602)
|
|
|
|
|
|
|
|
|
|
Net cash provided
by (used in) financing activities
|
46
|
|
|
40
|
|
|
(404)
|
|
|
(548)
|
|
Change in cash and
cash equivalents
|
1
|
|
|
(8)
|
|
|
(1)
|
|
|
(877)
|
|
Ending cash and
cash equivalents
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
5
|
|
|
|
(a)
|
Includes capitalized
interest of $2 million and $2 million for the three months ended
September 30, 2018 and 2017, respectively, and includes
capitalized interest of $7 million and $7 million for the nine
months ended September 30, 2018 and 2017,
respectively.
|
|
|
(b)
|
Includes capitalized
interest of $40 million and $47 million for the three months ended
September 30, 2018 and 2017, respectively, and includes
capitalized interest of $121 million and $139 million for the nine
months ended September 30, 2018 and 2017,
respectively.
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions
except per share data)
(unaudited)
|
|
|
Three Months Ended
September 30,
|
|
|
2018
|
|
2017
|
|
|
$
|
|
$/Share(a)(b)
|
|
$
|
|
$/Share(a)(b)
|
Net income (loss)
available to common stockholders (GAAP)
|
|
$
|
60
|
|
|
$
|
0.07
|
|
|
$
|
(41)
|
|
|
$
|
(0.05)
|
|
Effect of dilutive
securities
|
|
—
|
|
|
|
|
—
|
|
|
|
Diluted earnings
(losses) per common stockholder (GAAP)
|
|
$
|
60
|
|
|
$
|
0.07
|
|
|
$
|
(41)
|
|
|
$
|
(0.05)
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Unrealized losses on
oil, natural gas and NGL derivatives
|
|
9
|
|
|
0.01
|
|
|
101
|
|
|
0.12
|
|
Provision for legal
contingencies, net
|
|
8
|
|
|
0.01
|
|
|
20
|
|
|
0.02
|
|
Other operating
expense
|
|
—
|
|
|
—
|
|
|
6
|
|
|
0.01
|
|
Impairments
|
|
5
|
|
|
—
|
|
|
3
|
|
|
—
|
|
Net gains on sales of
fixed assets
|
|
—
|
|
|
—
|
|
|
(1)
|
|
|
—
|
|
Losses on purchases
or exchanges of debt
|
|
68
|
|
|
0.07
|
|
|
1
|
|
|
—
|
|
Income tax expense
(benefit)(c)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
|
|
—
|
|
|
—
|
|
|
(6)
|
|
|
(0.01)
|
|
Adjusted net
income available to common stockholders(a)
(Non-GAAP)
|
|
150
|
|
|
0.16
|
|
|
83
|
|
|
0.09
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
23
|
|
|
0.03
|
|
|
23
|
|
|
0.03
|
|
Earnings allocated to
participating securities
|
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total adjusted net
income attributable to Chesapeake(a) (b)
(Non-GAAP)
|
|
$
|
174
|
|
|
$
|
0.19
|
|
|
$
|
106
|
|
|
$
|
0.12
|
|
|
|
|
(a)
|
Adjusted net income
(loss) available to common stockholders and total adjusted net
income (loss) attributable to Chesapeake, both in the aggregate and
per dilutive share, are not measures of financial performance under
GAAP, and should not be considered as an alternative to, or more
meaningful than, net income (loss) available to common stockholders
or earnings (loss) per share. Adjusted net income (loss) available
to common stockholders and adjusted earnings (loss) per share
exclude certain items that management believes affect the
comparability of operating results. The company believes these
adjusted financial measures are a useful adjunct to earnings
calculated in accordance with GAAP because:
|
|
|
|
|
(i)
|
Management uses
adjusted net income (loss) available to common stockholders to
evaluate the company's operational trends and performance relative
to other oil and natural gas producing companies.
|
|
|
|
|
|
(ii)
|
Adjusted net income
(loss) available to common stockholders is more comparable to
earnings estimates provided by securities analysts.
|
|
|
|
|
(iii)
|
Items excluded
generally are one-time items or items whose timing or amount cannot
be reasonably estimated. Accordingly, any guidance provided
by the company generally excludes information regarding these types
of items.
|
|
|
|
|
|
Because adjusted net
income (loss) available to common stockholders and total adjusted
net income (loss) attributable to Chesapeake exclude some, but not
all, items that affect net income (loss) available to common
stockholders and total adjusted net income (loss) attributable to
Chesapeake may vary among companies, our calculation of adjusted
net income (loss) available to common stockholders and total
adjusted net income (loss) attributable to Chesapeake may not be
comparable to similarly titled financial measures of other
companies.
|
|
|
|
(b)
|
Our presentation of
diluted net income (loss) available to common stockholders and
diluted adjusted net income (loss) per share excludes 208 million
and 206 million shares considered antidilutive for the three months
ended September 30, 2018 and 2017, respectively. The number of
shares used for the non-GAAP calculation was determined in a manner
consistent with GAAP.
|
|
|
|
(c)
|
Our effective tax
rate in the three months ended September 30, 2018 was 0%. Due to
our valuation allowance position, no income tax effect from the
adjustments has been included in determining adjusted net income
for the three months ended September 30, 2017.
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
ADJUSTED NET INCOME AVAILABLE TO COMMON STOCKHOLDERS
($ in millions
except per share data)
(unaudited)
|
|
|
Nine Months Ended
September 30,
|
|
|
2018
|
|
2017
|
|
|
$
|
|
$/Share(a)(b)
|
|
$
|
|
$/Share(a)(b)
|
Net income
available to common stockholders (GAAP)
|
|
$
|
288
|
|
|
$
|
0.32
|
|
|
$
|
506
|
|
|
$
|
0.56
|
|
Effect of dilutive
securities
|
|
—
|
|
|
|
|
—
|
|
|
|
Diluted earnings per
common stockholder (GAAP)
|
|
$
|
288
|
|
|
$
|
0.32
|
|
|
$
|
506
|
|
|
$
|
0.56
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
|
296
|
|
|
0.32
|
|
|
(427)
|
|
|
(0.47)
|
|
Restructuring and
other termination costs
|
|
38
|
|
|
0.04
|
|
|
—
|
|
|
—
|
|
Provision for legal
contingencies, net
|
|
17
|
|
|
0.02
|
|
|
35
|
|
|
0.04
|
|
Other operating
expense (income)
|
|
(1)
|
|
|
—
|
|
|
423
|
|
|
0.47
|
|
Impairments
|
|
51
|
|
|
0.06
|
|
|
3
|
|
|
—
|
|
Net losses on sales
of fixed assets
|
|
7
|
|
|
0.01
|
|
|
—
|
|
|
—
|
|
Gains on
investments
|
|
(139)
|
|
|
(0.15)
|
|
|
—
|
|
|
—
|
|
(Gains) losses on
purchases or exchanges of debt
|
|
68
|
|
|
0.07
|
|
|
(183)
|
|
|
(0.21)
|
|
Loss on exchange of
preferred stock
|
|
—
|
|
|
—
|
|
|
41
|
|
|
0.05
|
|
Income tax expense
(benefit)(c)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other
(d)
|
|
(59)
|
|
|
(0.06)
|
|
|
(3)
|
|
|
—
|
|
Adjusted net
income available to common stockholders(a)
(Non-GAAP)
|
|
566
|
|
|
0.63
|
|
|
395
|
|
|
0.44
|
|
|
|
|
|
|
|
|
|
|
Preferred stock
dividends
|
|
69
|
|
|
0.07
|
|
|
62
|
|
|
0.07
|
|
Earnings allocated to
participating securities
|
|
3
|
|
|
—
|
|
|
7
|
|
|
—
|
|
Total adjusted net
income attributable to Chesapeake(a) (b)
(Non-GAAP)
|
|
$
|
638
|
|
|
$
|
0.70
|
|
|
$
|
464
|
|
|
$
|
0.51
|
|
|
|
|
(a)
|
Adjusted net income
(loss) available to common stockholders and total adjusted net
income (loss) attributable to Chesapeake, both in the aggregate and
per dilutive share, are not measures of financial performance under
GAAP, and should not be considered as an alternative to, or more
meaningful than, net income (loss) available to common stockholders
or earnings (loss) per share. Adjusted net income (loss) available
to common stockholders and adjusted earnings (loss) per share
exclude certain items that management believes affect the
comparability of operating results. The company believes these
adjusted financial measures are a useful adjunct to earnings
calculated in accordance with GAAP because:
|
|
|
|
|
(i)
|
Management uses
adjusted net income (loss) available to common stockholders to
evaluate the company's operational trends and performance relative
to other oil and natural gas producing companies.
|
|
|
|
|
(ii)
|
Adjusted net income
(loss) available to common stockholders is more comparable to
earnings estimates provided by securities analysts.
|
|
|
|
|
(iii)
|
Items excluded
generally are one-time items or items whose timing or amount cannot
be reasonably estimated. Accordingly, any guidance provided
by the company generally excludes information regarding these types
of items.
|
|
|
|
|
Because adjusted net
income (loss) available to common stockholders and total adjusted
net income (loss) attributable to Chesapeake exclude some, but not
all, items that affect net income (loss) available to common
stockholders and total adjusted net income (loss) attributable to
Chesapeake may vary among companies, our calculation of adjusted
net income (loss) available to common stockholders and total
adjusted net income (loss) attributable to Chesapeake may not be
comparable to similarly titled financial measures of other
companies.
|
|
|
|
(b)
|
Our presentation of
diluted net income (loss) available to common stockholders and
diluted adjusted net income (loss) per share excludes 207 million
and 207 million shares considered antidilutive for the nine months
ended September 30, 2018 and 2017, respectively. The number of
shares used for the non-GAAP calculation was determined in a manner
consistent with GAAP.
|
|
|
|
(c)
|
Our effective tax
rate in the nine months ended September 30, 2018 was 0%. Due to our
valuation allowance position, no income tax effect from the
adjustments has been included in determining adjusted net income
for the nine months ended September 30, 2017.
|
|
|
|
(d)
|
Other for the nine
months ended September 30, 2018 includes a $61 million gain related
to an extinguishment of the CHK Utica overriding royalty interest
conveyance obligation.
|
|
|
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
OPERATING CASH FLOW AND EBITDA
($ in
millions)
(unaudited)
|
|
Three Months
Ended
September 30,
|
|
Nine Months Ended September
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
$
|
504
|
|
|
$
|
331
|
|
|
$
|
1,595
|
|
|
$
|
273
|
|
Changes in components
of working capital and other assets and liabilities
|
(22)
|
|
|
6
|
|
|
(116)
|
|
|
366
|
|
OPERATING CASH
FLOW (Non-GAAP)(a)
|
$
|
482
|
|
|
$
|
337
|
|
|
$
|
1,479
|
|
|
$
|
639
|
|
|
|
Three Months Ended September
30,
|
|
Nine Months Ended September
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS)
(GAAP)
|
$
|
85
|
|
|
$
|
(17)
|
|
|
$
|
363
|
|
|
$
|
619
|
|
Interest
expense
|
127
|
|
|
114
|
|
|
367
|
|
|
302
|
|
Income tax expense
(benefit)
|
1
|
|
|
—
|
|
|
(8)
|
|
|
2
|
|
Depreciation and
amortization of other assets
|
17
|
|
|
20
|
|
|
54
|
|
|
62
|
|
Oil, natural gas and
NGL depreciation, depletion and amortization
|
274
|
|
|
228
|
|
|
813
|
|
|
627
|
|
EBITDA
(Non-GAAP)(b)
|
$
|
504
|
|
|
$
|
345
|
|
|
$
|
1,589
|
|
|
$
|
1,612
|
|
|
|
Three Months Ended September
30,
|
|
Nine Months Ended September
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY
OPERATING ACTIVITIES (GAAP)
|
$
|
504
|
|
|
$
|
331
|
|
|
$
|
1,595
|
|
|
$
|
273
|
|
Changes in assets and
liabilities
|
(22)
|
|
|
6
|
|
|
(116)
|
|
|
366
|
|
Interest
expense
|
127
|
|
|
114
|
|
|
367
|
|
|
302
|
|
Gains (losses) on
oil, natural gas and NGL derivatives, net
|
(132)
|
|
|
(70)
|
|
|
(500)
|
|
|
452
|
|
Cash (receipts)
payments on derivative settlements, net
|
107
|
|
|
(20)
|
|
|
162
|
|
|
46
|
|
Stock-based
compensation
|
(7)
|
|
|
(11)
|
|
|
(25)
|
|
|
(38)
|
|
Impairments
|
(5)
|
|
|
(3)
|
|
|
(51)
|
|
|
(3)
|
|
Gains (losses) on
sales of fixed assets
|
—
|
|
|
1
|
|
|
(7)
|
|
|
—
|
|
Gains on
investments
|
—
|
|
|
—
|
|
|
139
|
|
|
—
|
|
Gains (losses) on
purchases or exchanges of debt
|
(68)
|
|
|
—
|
|
|
(68)
|
|
|
185
|
|
Other items
(c)
|
—
|
|
|
(3)
|
|
|
93
|
|
|
29
|
|
EBITDA
(Non-GAAP)(b)
|
$
|
504
|
|
|
$
|
345
|
|
|
$
|
1,589
|
|
|
$
|
1,612
|
|
|
|
(a)
|
Operating cash flow
represents net cash provided by operating activities before changes
in components of working capital and other. Operating cash flow is
presented because management believes it is a useful adjunct to net
cash provided by operating activities under GAAP and provides
useful information to investors for analysis of the Company's
ability to generate cash to fund exploration and development, and
to service debt. Operating cash flow is widely accepted as a
financial indicator of an oil and natural gas company's ability to
generate cash that is used to internally fund exploration and
development activities and to service debt. This measure is widely
used by investors and rating agencies in the valuation, comparison,
rating and investment recommendations of companies within the oil
and natural gas exploration and production industry. Operating cash
flow is not a measure of financial performance under GAAP and
should not be considered as an alternative to cash flows from
operating activities as an indicator of cash flows, or as a measure
of liquidity. Because operating cash flow excludes some, but not
all, items that affect net cash provided by operating activities
and may vary among companies, our calculation of operating cash
flow may not be comparable to similarly titled measures of other
companies. The increase in operating cash flow for the nine months
ended September 30, 2018 is mainly due to an increase in realized
prices and volumes.
|
|
|
(b)
|
EBITDA represents net
income before interest expense, income tax expense, and
depreciation, depletion and amortization expense. EBITDA is
presented as a supplemental financial measurement in the evaluation
of our business. We believe that it provides additional information
regarding our ability to meet our future debt service, capital
expenditures and working capital requirements. This measure is
widely used by investors and rating agencies in the valuation,
comparison, rating and investment recommendations of companies.
EBITDA is also a financial measurement that, with certain
negotiated adjustments, is reported to our lenders pursuant to our
bank credit agreements and is used in the financial covenants in
our bank credit agreements. EBITDA is not a measure of financial
performance (or liquidity) under GAAP. Accordingly, it should not
be considered as a substitute for net income, income from
operations or cash flows from operating activities prepared in
accordance with GAAP.
|
|
|
(c)
|
Other items for the
nine months ended September 30, 2018 includes a $61 million gain
related to an extinguishment of the CHK Utica overriding royalty
interest conveyance obligation.
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
RECONCILIATION OF
ADJUSTED EBITDA
($ in
millions)
(unaudited)
|
|
Three Months Ended September
30,
|
|
Nine Months Ended September
30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
|
|
|
|
|
|
|
EBITDA (Non-GAAP)
(a)
|
$
|
504
|
|
|
$
|
345
|
|
|
$
|
1,589
|
|
|
$
|
1,612
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
Unrealized (gains)
losses on oil, natural gas and NGL derivatives
|
9
|
|
|
101
|
|
|
296
|
|
|
(427)
|
|
Restructuring and
other termination costs
|
—
|
|
|
—
|
|
|
38
|
|
|
—
|
|
Provision for legal
contingencies, net
|
8
|
|
|
20
|
|
|
17
|
|
|
35
|
|
Other operating
expense (income)
|
—
|
|
|
6
|
|
|
(1)
|
|
|
423
|
|
Impairments
|
5
|
|
|
3
|
|
|
51
|
|
|
3
|
|
(Gains) losses on
sales of fixed assets
|
—
|
|
|
(1)
|
|
|
7
|
|
|
—
|
|
Gains on
investments
|
—
|
|
|
—
|
|
|
(139)
|
|
|
—
|
|
(Gains) losses on
purchases or exchanges of debt
|
68
|
|
|
1
|
|
|
68
|
|
|
(183)
|
|
Net income
attributable to noncontrolling interests
|
(1)
|
|
|
(1)
|
|
|
(3)
|
|
|
(3)
|
|
Other
(b)
|
1
|
|
|
(6)
|
|
|
(60)
|
|
|
(6)
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
(Non-GAAP)(a)
|
$
|
594
|
|
|
$
|
468
|
|
|
$
|
1,863
|
|
|
$
|
1,454
|
|
|
|
(a)
|
EBITDA and Adjusted
EBITDA are not measures of financial performance under GAAP, and
should not be considered as an alternative to, or more meaningful
than, net income (loss) or cash flow provided by (used in)
operations prepared in accordance with GAAP. Adjusted EBITDA
excludes certain items that management believes affect the
comparability of operating results. The company believes these
non-GAAP financial measures are a useful adjunct to EBITDA
because:
|
|
|
|
(i)
|
Management uses
adjusted EBITDA to evaluate the company's operational trends and
performance relative to other oil and natural gas producing
companies.
|
|
|
|
|
(ii)
|
Adjusted EBITDA is
more comparable to estimates provided by securities
analysts.
|
|
|
|
|
(iii)
|
Items excluded
generally are one-time items or items whose timing or amount cannot
be reasonably estimated. Accordingly, any guidance provided by the
company generally excludes information regarding these types of
items.
|
|
|
|
|
Because adjusted
EBITDA excludes some, but not all, items that affect net income,
our calculations of adjusted EBITDA may not be comparable to
similarly titled measures of other companies.
|
|
|
(b)
|
Other for the nine
months ended September 30, 2018 includes a $61 million gain related
to an extinguishment of the CHK Utica overriding royalty interest
conveyance obligation.
|
|
|
|
|
|
|
CHESAPEAKE ENERGY
CORPORATION
|
MANAGEMENT'S
OUTLOOK AS OF OCTOBER 30, 2018
|
|
Chesapeake
periodically provides guidance on certain factors that affect the
company's future financial performance. New information or changes
from the company's August 1, 2018 outlook are italicized
bold below.
|
|
|
Year
Ending
12/31/2018
|
|
|
Production Growth
adjusted for asset sales(a)
|
1% to 5%
|
Absolute
Production
|
|
Liquids -
mmbbls
|
48.5 -
52.5
|
Oil -
mmbbls
|
31.5 -
33.5
|
NGL -
mmbbls
|
17.0 -
19.0
|
Natural gas -
bcf
|
790 - 830
|
Total absolute
production - mmboe
|
180 - 191
|
Absolute daily rate -
mboe
|
494 - 524
|
Estimated
Realized Hedging Effects(b) (based on 10/25/18 strip
prices):
|
|
Oil -
$/bbl
|
($11.85)
|
Natural gas -
$/mcf
|
$0.07
|
NGL -
$/bbl
|
$(0.95)
|
Estimated Basis
to NYMEX Prices:
|
|
Oil -
$/bbl
|
$2.05 -
$2.25
|
Natural gas -
$/mcf
|
($0.10) -
($0.15)
|
NGL -
$/bbl
|
($6.20) -
($6.60)
|
Operating Costs per
Boe of Projected Production:
|
|
Production
expense
|
$2.85 -
$2.95
|
Gathering, processing
and transportation expenses
|
$6.85 -
$7.35
|
Oil -
$/bbl
|
$3.60 -
$3.80
|
Natural Gas -
$/mcf
|
$1.25 -
$1.35
|
NGL -
$/bbl
|
$8.25 -
$8.65
|
Production
taxes
|
$0.60 -
$0.70
|
General and
administrative(c)
|
$1.25 -
$1.35
|
Stock-based
compensation (noncash)
|
$0.10 -
$0.20
|
DD&A of natural
gas and liquids assets
|
$5.25 -
$6.25
|
Depreciation of other
assets
|
$0.35 -
$0.45
|
Interest
expense
|
$2.40 -
$2.60
|
Marketing net
margin(d)
|
($55) -
($35)
|
Book Tax
Rate
|
0%
|
Adjusted
EBITDA, based on 10/25/18 strip prices ($ in
millions)(e)
|
$2,300 -
$2,500
|
Capital Expenditures
($ in millions)(f)
|
$2,000 -
$2,300
|
Capitalized Interest
($ in millions)
|
$175
|
Total Capital
Expenditures ($ in millions)
|
$2,175 -
$2,475
|
|
|
(a)
|
Based on 2017
production of 407 mboe per day, adjusted for 2017 asset sales and
2018 asset sales signed to date.
|
|
|
(b)
|
Includes expected
settlements for oil, natural gas and NGL derivatives adjusted for
option premiums. For derivatives closed early, settlements are
reflected in the period of original contract expiration.
|
|
|
(c)
|
Excludes expenses
associated with stock-based compensation, which are recorded in
general and administrative expenses in Chesapeake's Consolidated
Statement of Operations.
|
|
|
(d)
|
Excludes non-cash
amortization of approximately $19 million.
|
|
|
(e)
|
Adjusted EBITDA is a
non-GAAP measure used by management to evaluate the company's
operational trends and performance relative to other oil and
natural gas producing companies. Adjusted EBITDA excludes certain
items that management believes affect the comparability of
operating results. The most directly comparable GAAP measure is net
income but, it is not possible, without unreasonable efforts, to
identify the amount or significance of events or transactions that
may be included in future GAAP net income but that management does
not believe to be representative of underlying business
performance. The company further believes that providing estimates
of the amounts that would be required to reconcile forecasted
adjusted EBITDA to forecasted GAAP net income would imply a degree
of precision that may be confusing or misleading to investors.
Items excluded from net income to arrive at adjusted EBITDA include
interest expense, income taxes, and depreciation, depletion and
amortization expense as well as one-time items or items whose
timing or amount cannot be reasonably estimated.
|
|
|
(f)
|
Includes capital
expenditures for drilling and completion, leasehold, geological and
geophysical costs, rig termination payments and other property,
plant and equipment. Excludes any additional proved property
acquisitions.
|
|
|
|
|
Oil, Natural Gas and Natural Gas Liquids Hedging
Activities
Chesapeake enters into oil,
natural gas and NGL derivative transactions in order to mitigate a
portion of its exposure to adverse changes in market prices. Please
see the quarterly reports on Form 10-Q and annual reports on Form
10-K filed by Chesapeake with the
SEC for detailed information about derivative instruments the
company uses, its quarter-end derivative positions and accounting
for oil, natural gas and natural gas liquids derivatives.
As of October 26, 2018, including
October derivative contracts that have settled, the company had
downside price protection on a portion of its 2018 oil, natural gas
and natural gas liquids production. The company had downside oil
price protection through swaps at an average price of $54.09 per bbl, and under three-way collar
arrangements based on an average bought put NYMEX price of
$47.00 per bbl and exposure below an
average sold put NYMEX price of $39.15 per bbl. The company had downside natural
gas price protection through swaps and two-way collars at an
average price of $3.00 per mcf.
Chesapeake also had downside
ethane, propane, butane, isobutane and natural gasoline price
protection through swaps at an average price of $0.29, $0.79,
$0.88, $0.92 and $1.42 per
gallon (as well as a portion of butane at 70.5 percent of WTI),
respectively. Further details summarized below.
In addition, the company had downside protection, through open
swaps on a portion of its 2019 oil production at an average price
of $59.44 per bbl. The company also
initiated downside protection on a portion of its 2019 natural gas
production through open swaps and two-way collars at an average
price of $2.82 per mcf and under
three-way collar arrangements based on an average bought put NYMEX
price of $2.80 per mcf and exposure
below an average sold put NYMEX price of $2.50 per mcf.
The company's crude oil hedging positions were as follows:
Crude Oil
Swaps
Losses from Closed
Crude Oil Trades
|
|
Swaps
(mmbbls)
|
|
Avg.
NYMEX
Price
of
Swaps
|
|
Losses from
Closed Trades
($ in
millions)
|
|
|
|
|
|
|
Q4 2018
|
7
|
|
$
|
54.09
|
|
|
(1)
|
|
Total 2018
|
7
|
|
$
|
54.09
|
|
|
$
|
(1)
|
|
|
|
|
|
|
|
Q1 2019
|
4
|
|
$
|
59.06
|
|
|
(1)
|
|
Q2 2019
|
4
|
|
$
|
59.06
|
|
|
(1)
|
|
Q3 2019
|
3
|
|
$
|
59.96
|
|
|
(1)
|
|
Q4 2019
|
3
|
|
$
|
59.96
|
|
|
(1)
|
|
Total 2019
|
14
|
|
$
|
59.44
|
|
|
$
|
(4)
|
|
|
|
|
|
|
|
Total
2020-2022
|
3
|
|
$
|
69.47
|
|
|
$
|
(4)
|
|
|
|
Crude Oil
Three-Way Collars
|
|
|
Collars
(mmbbls)
|
|
Avg. NYMEX
Sold Put Price
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
|
|
|
Q4 2018
|
|
1
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
Total 2018
|
|
1
|
|
$
|
39.15
|
|
|
$
|
47.00
|
|
|
$
|
55.00
|
|
|
|
Oil Basis
Protection Swaps
|
|
Volume
(mmbbls)
|
|
Avg.
NYMEX
plus/(minus)
|
|
|
|
|
Q4 2018
|
4
|
|
$
|
3.52
|
|
Total 2018
|
4
|
|
$
|
3.52
|
|
|
|
|
|
Q1 2019
|
2
|
|
$
|
5.93
|
|
Q2 2019
|
3
|
|
$
|
5.93
|
|
Q3 2019
|
1
|
|
$
|
6.20
|
|
Q4 2019
|
1
|
|
$
|
6.20
|
|
Total 2019
|
7
|
|
$
|
6.01
|
|
The company's natural gas hedging positions were as follows:
Natural Gas
Swaps
Losses from Closed
Natural Gas Trades
|
|
Swaps
(bcf)
|
|
Avg.
NYMEX
Price
of
Swaps
|
|
Losses
from Closed
Trades
($ in
millions)
|
|
|
|
|
|
|
Q4 2018
|
120
|
|
$
|
3.00
|
|
|
(5)
|
|
Total 2018
|
120
|
|
$
|
3.00
|
|
|
$
|
(5)
|
|
|
|
|
|
|
|
Q1 2019
|
81
|
|
$
|
2.83
|
|
|
(6)
|
|
Q2 2019
|
81
|
|
$
|
2.83
|
|
|
(4)
|
|
Q3 2019
|
82
|
|
$
|
2.83
|
|
|
(4)
|
|
Q4 2019
|
81
|
|
$
|
2.83
|
|
|
(5)
|
|
Total 2019
|
325
|
|
$
|
2.83
|
|
|
$
|
(19)
|
|
|
|
|
|
|
|
Total 2020 -
2022
|
—
|
|
$
|
—
|
|
|
$
|
(29)
|
|
|
|
Natural Gas
Two-Way Collars
|
|
Collars
(bcf)
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
Q4 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
Total 2018
|
12
|
|
$
|
3.00
|
|
|
$
|
3.25
|
|
|
|
|
|
|
|
Q1 2019
|
27
|
|
$
|
2.75
|
|
|
$
|
3.13
|
|
Q2 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q3 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Q4 2019
|
9
|
|
$
|
2.75
|
|
|
$
|
2.91
|
|
Total 2019
|
54
|
|
$
|
2.75
|
|
|
$
|
3.02
|
|
|
|
Natural Gas
Three-Way Collars
|
|
|
Collars
(bcf)
|
|
Avg. NYMEX
Sold Put Price
|
|
Avg. NYMEX
Bought Put Price
|
|
Avg. NYMEX
Sold Call Price
|
|
|
|
|
|
|
|
|
|
Q1 2019
|
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Q2 2019
|
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Q3 2019
|
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Q4 2019
|
|
22
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
Total 2019
|
|
88
|
|
$
|
2.50
|
|
|
$
|
2.80
|
|
|
$
|
3.10
|
|
|
|
Natural Gas Net
Written Call Options
|
|
Call
Options
(bcf)
|
|
Avg.
NYMEX
Strike
Price
|
|
|
|
|
Q4 2018
|
17
|
|
$
|
6.27
|
|
Total 2018
|
17
|
|
$
|
6.27
|
|
|
|
|
|
Q1 2019
|
5
|
|
$
|
12.00
|
|
Q2 2019
|
5
|
|
$
|
12.00
|
|
Q3 2019
|
6
|
|
$
|
12.00
|
|
Q4 2019
|
6
|
|
$
|
12.00
|
|
Total 2019
|
22
|
|
$
|
12.00
|
|
|
|
|
|
Total 2020
|
22
|
|
$
|
12.00
|
|
|
|
Natural Gas Basis
Protection Swaps
|
|
Volume
(bcf)
|
|
Avg. NYMEX
plus/(minus)
|
|
|
|
|
Q4 2018
|
6
|
|
$
|
(0.77)
|
|
Total 2018
|
6
|
|
$
|
(0.77)
|
|
|
|
|
|
Q1 2019
|
7
|
|
$
|
1.07
|
|
Q2 2019
|
12
|
|
$
|
(0.17)
|
|
Q3 2019
|
12
|
|
$
|
(0.17)
|
|
Q4 2019
|
6
|
|
$
|
(0.39)
|
|
Total 2019
|
37
|
|
$
|
0.03
|
|
The company's natural gas liquids hedging positions were as
follows:
Ethane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q4 2018
|
23
|
|
$
|
0.29
|
|
Total 2018
|
23
|
|
$
|
0.29
|
|
|
|
Propane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q4 2018
|
15
|
|
$
|
0.79
|
|
Total 2018
|
15
|
|
$
|
0.79
|
|
|
|
Butane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q4 2018
|
1
|
|
$
|
0.88
|
|
Total 2018
|
1
|
|
$
|
0.88
|
|
|
|
Butane Swaps
Priced as a Percentage of WTI
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
as a % of WTI Swaps
|
|
|
|
|
Q4 2018
|
1
|
|
70.5%
|
Total 2018
|
1
|
|
70.5%
|
|
|
Iso-Butane
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q4 2018
|
4
|
|
$
|
0.92
|
|
Total 2018
|
4
|
|
$
|
0.92
|
|
|
|
Natural Gasoline
Swaps
|
|
Volume
(mmgal)
|
|
Avg. NYMEX
Price of Swaps
|
|
|
|
|
Q4 2018
|
12
|
|
$
|
1.42
|
|
Total 2018
|
12
|
|
$
|
1.42
|
|
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SOURCE Chesapeake Energy Corporation